Freehold Royalties Ltd.

Freehold Royalties Ltd.

November 09, 2011 17:01 ET

Freehold Royalties Ltd. Announces 2011 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 9, 2011) - Freehold Royalties Ltd. (Freehold) (TSX:FRU) today announced third quarter results for the period ended September 30, 2011.

Results at a Glance

Three Months Ended Nine Months Ended
September 30 September 30
FINANCIAL ($000s, except as noted) 2011 2010 Change 2011 2010 Change
Gross revenue 35,819 32,637 10 % 112,606 101,630 11 %
Net income 11,290 12,999 -13 % 39,226 37,962 3 %
Per share, basic and diluted ($) (1) 0.19 0.22 -14 % 0.66 0.65 2 %
Cash provided by operating activities 30,255 26,704 13 % 85,775 82,678 4 %
Per share ($) (1) 0.50 0.46 9 % 1.44 1.42 1 %
Funds generated from operations (2) 28,772 25,811 11 % 89,985 78,753 14 %
Per share ($) (1) 0.48 0.44 9 % 1.51 1.36 11 %
Capital expenditures 5,537 6,003 -8 % 14,739 13,390 10 %
Property and royalty acquisitions (net) 7,297 (153 ) - 7,662 38,317 -80 %
Dividends declared 25,322 24,617 3 % 75,383 73,318 3 %
Per share ($) (1) (3) 0.42 0.42 0 % 1.26 1.26 0 %
Long-term debt, period end 51,000 70,000 -27 % 51,000 70,000 -27 %
Shareholders' equity, period end 271,397 287,053 -5 % 271,397 287,053 -5 %
Shares outstanding, period end (000s) 60,492 58,781 3 % 60,492 58,781 3 %
Average shares outstanding (000s) (4) 60,198 58,536 3 % 59,756 58,119 3 %
Average daily production (boe/d) (5) 7,195 7,495 -4 % 7,376 7,494 -2 %
Average price realizations ($/boe) (5) 52.80 46.44 14 % 54.32 48.72 12 %
Operating netback ($/boe) (2) (5) 46.86 41.56 13 % 49.92 43.89 14 %
  1. Prior to conversion to a corporation on December 31, 2010, Freehold had trust units outstanding instead of shares.
  2. See Non-GAAP Financial Measures.
  3. Based on the number of shares issued and outstanding at each record date.
  4. Weighted average number of shares outstanding during the period, basic.
  5. See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).

Freehold's assets delivered strong results for the third quarter of 2011, despite commodity price volatility and the lingering effects of wet operating conditions in June and July. Our 62% oil-weighted production continued to benefit from robust oil prices: revenue, operating netback, and funds generated from operations were all substantially higher than last year's cash metrics. Net income declined 13% due to an increase in deferred income tax. Non-cash charges included in net income amounted to $17.7 million in the third quarter of 2011 (2010 Q3 – $13.0 million) and were $53.4 million for the year to date (2010 YTD – $42.7 million). Per share amounts reflect increased participation in our dividend reinvestment plan.

Commodity Prices

Crude oil prices were higher than last year despite a stronger Canadian dollar, residual pipeline capacity constraints, and widening heavy oil differentials. However, WTI crude oil prices declined 12% from July to September. The bearish sentiment was driven by global economic and political uncertainties, including the U.S. debt ceiling impasse, the European debt crisis, and a cooling of the Chinese economy. As well, a transportation bottleneck out of North American inland markets has served to dislocate the WTI crude oil benchmark from other light oil benchmarks such as European Brent Crude, creating a significant price discount for WTI. Oil prices are expected to remain volatile in the short term, with both upside and downside risks.

Historically, the benchmark Western Canada Select (WCS) heavy oil stream, with an average API gravity of 20.5 degrees, was considered a rough proxy for our average oil price realizations. However, in 2011 our average oil realizations increased in relation to the benchmark WCS.

The outlook for natural gas prices remains bearish in the near term, as supply continues to outstrip demand in North America. As the winter heating season approaches, predictions for a return of a La Niña weather pattern could bring prolonged cold weather to the Northern Hemisphere, which would increase natural gas consumption. Longer-term, projects are underway to open access to high-demand Asian markets as early as 2015. The National Energy Board recently granted a 20-year export licence to Kitimat LNG to ship liquefied natural gas from Canada to international markets, and approvals are in place for the construction of the Pacific Trail Pipeline, which will connect natural gas from the Western Canada Sedimentary Basin to the Kitimat LNG facility at Bish Cove, British Columbia.

Industry Drilling

Many industry operators experienced drilling and production delays in the third quarter due to forest fires in northern Alberta and flooding in southeastern Saskatchewan. As well, the weather-related delays have increased competition for goods and services, adding to growing industry inflationary pressures. Despite this challenging operating environment, industry drilled 3,861 wells in the third quarter, a 40% increase over last year. Nearly 70% of the wells drilled were oil, and horizontal drilling techniques continue to be employed to access tight reservoirs and other resource plays.

Royalty Interests

It was also a good quarter for drilling on our royalty lands. On an equivalent net basis, drilling was up 28% from the same period last year, and non-unitized drilling was up 19%. The trend towards horizontal drilling continued, as 70% of these wells were horizontal compared to 53% in the third quarter last year. A single horizontal well, with multiple fracs, can access as much reservoir as several vertical wells, potentially yielding more production and reserves per well. Given our extensive royalty land holdings, we are well positioned to participate in many of the developing resource plays. The most promising opportunities for us are in areas south of the North Saskatchewan River in Alberta and in Southeast Saskatchewan where we own significant mineral title lands.

As at September 30, 2011, there were 118 (5.0 equivalent net) licensed drilling locations on our royalty lands, up from 117 (3.2 equivalent net) at the same time last year. We view well licence activity as a positive indicator of the ongoing and future development potential on our royalty lands.

Working Interests

In the third quarter, we participated in the drilling of eight (3.2 net) oil wells with a 100% success rate. The wells had little effect on production levels in the third quarter but will add to our production in the fourth quarter. In Saskatchewan, wet weather conditions limited access for much of the quarter. We drilled one (0.9 net) Bakken light oil well and one (0.5 net) Alida light oil well; both were horizontal wells. In Alberta, we drilled one (0.3 net) horizontal Boundary Lake light oil well at Pouce Coupe and three (0.9 net) vertical Sparky heavy oil wells at Consort. In addition, we completed our infill program at Hayter, drilling only two of four planned Dina heavy oil wells – one (0.2 net) vertical well and one (0.4 net) horizontal well. This was a reduction from our historical infill program of 10 wells per year for the last 10 years as we are approaching the limits of well density. Two infill locations have been deferred pending an assessment of performance of the first two wells. Production at Hayter averaged 240 boe per day in the third quarter, down from 340 boe per in the third quarter last year. An enhanced oil recovery study is underway to evaluate the feasibility of pattern flooding to change sweep patterns and recover incremental oil.

Royalty Acquisition

On September 30, 2011, we closed an acquisition of certain royalty interests for $7.3 million, after closing adjustments, which will add approximately 100 boe per day of primarily light oil to our royalty production base commencing in the fourth quarter. We acquired a 10% gross overriding royalty interest on 5,048 gross acres of land in the Peace River area of Northwest Alberta. Reserves were independently evaluated at approximately 203,000 boe proved plus probable effective July 1, 2011, with an estimated reserve life index of 4.8 years. The agreement provides for additional payments to the vendor of up to $3.2 million if additional wells are drilled before December 31, 2013. The acquisition supports our strategy of focusing on oil and gas royalties and is accretive on a debt-adjusted per share basis. The acquisition was effective July 1, 2011 and was funded through our existing credit facilities.

Dividend Policy

The Board reviews and determines the dividend rate quarterly after considering expected commodity prices, foreign exchange rates, economic conditions, production volumes, DRIP participation levels, tax payable, and our capacity to finance operating and investing obligations. The dividend rate is established with the intent of absorbing short-term market volatility over several months. It also recognizes our intention to fund capital expenditures primarily through funds generated from operations and to maintain a strong balance sheet to take advantage of acquisition opportunities and withstand potential commodity price declines.

November Dividend Announcement

The Board of Directors has declared the November dividend of $0.14 per share, which will be paid on December 15, 2011 to shareholders of record on November 30, 2011 (ex-dividend date November 28, 2011). Including the December 15 payment, our 12-month trailing cash dividends total $1.68 per share (including the distributions paid on trust units of Freehold Royalty Trust prior to conversion). This dividend is designated as an eligible dividend for Canadian income tax purposes.

Guidance Update

Subject to availability of services, capital investment in the fourth quarter of the year is expected to be $7 million, bringing total investment for the year to $22 million. The majority of spending ($4.5 million) will be in Southeast Saskatchewan where we plan to drill four (2.25 net) horizontal oil wells, of which two (1.25 net) will be in the Bakken.

The following table summarizes our key operating assumptions, updated to reflect actual results for the first nine months of 2011 and our current expectations for the remainder of the year. The changes are relatively minor and reflect the following factors:

  • We have adjusted our oil price assumptions to reflect lower WTI prices and wider price differentials for heavy oil in the second half of 2011 compared to the first half of the year.
  • General and administrative expenses are anticipated to be about $0.50 per boe lower, largely as a result of lower than anticipated reorganization costs.
  • Proceeds from the dividend reinvestment plan (DRIP) are expected to be about $5 million higher than previously anticipated as a result of increased participation.
  • Long-term debt at year-end is anticipated to be $2.0 million higher than previously estimated due to projected lower crude oil price realizations projected for the fourth quarter of 2011.

2011 Key Operating Assumptions

Nov. 9 Aug. 10 May 11 Mar. 2
2011 2011 2011 2011
Average daily production boe/d 7,300 7,300 7,100 7,100
Average WTI oil price US$/bbl 94.00 95.00 90.00 80.00
Average exchange rate Cdn$/US$ 1.03 1.03 1.00 0.95
Average heavy oil price differential (1) Cdn$/bbl 19.50 19.00 15.00 13.00
Average AECO natural gas price Cdn$/Mcf 3.65 3.65 3.65 4.25
Average operating costs $/boe 4.50 4.50 4.50 4.50
Average general and administrative costs (2) $/boe 3.00 3.50 3.50 3.50
Capital expenditures $ millions 22 22 28 20
Proceeds from DRIP $ millions 33 28 28 27
Long-term debt at year end $ millions 43 41 50 50
Cash taxes payable $ millions - - - -
Weighted average shares outstanding millions 60 60 60 60
(1) The difference between the Edmonton Par and Western Canada Select crude oil streams.
(2) Excludes share based and other compensation.
Nov. 9
2012 Key Operating Assumptions 2011
Average daily production boe/d 7,100
Average WTI oil price US$/bbl 92.00
Average exchange rate Cdn$/US$ 0.98
Average heavy oil price differential (1) Cdn$/bbl 20.00
Average AECO natural gas price Cdn$/Mcf 3.75
Average operating costs $/boe 4.60
Average general and administrative costs (2) $/boe 3.00
Capital expenditures $ millions 30
Proceeds from DRIP $ millions 27
Long-term debt at year end $ millions 37
Cash taxes payable (3) $ millions 2
Weighted average shares outstanding millions 62

(1) The difference between the Edmonton Par and Western Canada Select crude oil streams.

(2) Excludes share based and other compensation.

(3) Cash taxes payable in 2012 based on three months of 2011 taxable income as the partnership has a March 31 year-end.

For 2012, the Board has approved a capital budget of $30 million, the largest in our history. Our plans include 65 (19.5 net) wells, of which 65% will be operated. About 80% of our capital will be deployed on our mineral title lands in Southeast Saskatchewan, where we continue to see opportunities. Spending may be adjusted as the year progresses, depending on the operating environment and well results. Based on this level of capital investment, anticipated drilling activity on our leased royalty lands, and normal production declines (and excluding any potential acquisitions), we expect 2012 production to average approximately 7,100 boe per day.

Up until December 31, 2010, our trust structure was such that both current income tax and deferred tax liabilities were passed on to our unitholders. With our conversion from a trust to a corporation on December 31, 2010, we became subject to normal corporate tax rates starting in 2011. The corporate income tax rate applicable to 2011 is 26.5%; however, we did not pay any corporate income tax in the first nine months of 2011 (2010 – $nil) and we do not expect to pay any corporate income tax in the fourth quarter of 2011 due to the tax deductions available to us and the effect of the deferral of our partnership income.

On October 3, 2011, the finance minister tabled a notice of ways and means motion to implement tax measures outlined in the 2011 budget (Bill C-13), which included a proposal to eliminate the ability of a corporation to defer income as a result of timing differences in the year-end of the corporation and of any partnership of which it is a member, subject to transitional relief over five years. Bill C-13 is expected to be passed into law in the near future. We anticipate being able to take advantage of the transitional relief.

The corporate income tax rate applicable to 2012 is 25%. Current taxes payable will be subject to normal corporate tax rates. Taxable income as a corporation is based on total income and expenses (which will vary depending on commodity prices, production volumes, and costs), reduced by claims for both accumulated tax pools and tax pools associated with current year expenditures. To the end of 2010, we had accumulated approximately $235 million of income tax pools for federal tax purposes. These income tax pools (detailed on page 14 of our 2010 Financial Report) are deductible at various rates. As our partnership has a March 31 year-end, we expect to pay cash income taxes of approximately $2 million in 2012. In the first quarter of 2013, we expect to pay cash taxes on a full year of taxable income.

We have $159 million of available capacity under our credit facilities which gives us financial flexibility to take advantage of acquisition opportunities. In addition, cash preserved through our DRIP continues to enhance our ability to fund our capital program, strengthen our balance sheet, and pursue acquisition opportunities, while allowing us to maintain a high dividend payout ratio. We have maintained a steady monthly dividend rate of $0.14 ($1.68 annually) per share since January 2010. Based on our initial 2012 guidance, we expect to maintain the current monthly dividend rate through 2012, subject to the Board's quarterly review.

Availability on SEDAR

Freehold's 2011 third quarter report, including unaudited financial statements and Management's Discussion and Analysis, is being filed today with Canadian securities regulators and will be available on SEDAR at or on our website.

Forward-Looking Statements

This news release offers our assessment of Freehold's future plans and operations as at November 9, 2011, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements include our expectations for the following:

  • our outlook for commodity prices including supply and demand factors relating to crude oil, heavy oil, and natural gas;
  • light/heavy oil price differentials;
  • changing economic conditions;
  • completion of pipeline projects and the timing thereof;
  • foreign exchange rates;
  • industry drilling, development activity on our royalty lands, our participation in emerging resource plays, and the potential impact of horizontal drilling on production and reserves;
  • development of working interest properties;
  • participation in the DRIP and our use of cash preserved through the DRIP;
  • estimated capital expenditures and the timing thereof;
  • long-term debt at year end;
  • average production and contribution from royalty lands;
  • key operating assumptions;
  • acquisition opportunities;
  • deferred income tax and our expected taxability; and
  • our dividend policy.

Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe", and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our AIF.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future oil and natural gas prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future participation rates in the DRIP and use of cash preserved through the DRIP, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in the body of this news release.

You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.

Conversion of Natural Gas To Barrels of Oil Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation.

Non-GAAP Financial Measures

Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that operating netback and funds generated from operations are useful supplemental measures for management and investors to analyze operating performance, financial leverage, and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations and financial position. However, these terms do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis.

Funds generated from operations is a financial term commonly used in the oil and natural gas industry. It represents cash provided by operating activities before changes in non-cash working capital and is a key measure of our ability to generate cash, finance operations, and pay monthly dividends. Funds generated from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with GAAP. The key difference between cash provided by operating activities and funds generated from operations is changes in non-cash working capital, which is affected by accounts receivable, accounts payable, and accrued liabilities. Accounts receivable, and therefore working capital, can fluctuate greatly between reporting periods due to timing of receipt of payments. In the event that commodity prices and/or volumes have changed significantly from the previous reporting period, a significant difference could occur between cash provided by operating activities and funds generated from operations. All references to funds generated from operations throughout this report are based on cash provided by operating activities before changes in non-cash working capital as per the Statements of Cash Flows. Funds generated from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.

In addition, we refer to various per boe figures, such as revenues and costs, also considered non-GAAP measures, which provide meaningful information on our operational performance. We derive per boe figures by dividing the relevant revenue or cost figure by the total volume of oil and natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.

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